Yesterday, we released an update of our 2012 Ripe for Retirement study that was published in the Electricity Journal, which analyzed the economic viability of updating the nation’s coal fleet compared to investing in cleaner alternatives. (For more details on the study, see this blog by my colleague Jeff Deyette.) Thanks to new technology developments that have lowered the costs of new wind projects and increased electricity production, our new analysis shows wind power could play an even greater role than natural gas in replacing existing coal plants.

The analysis shows that retrofitting 71 gigawatts (GW) of existing U.S. coal capacity with modern pollution controls would be more expensive than the cost of building new wind projects with the federal production tax credit (PTC) included. This is 12 GW, or 21 percent, higher than our core scenario comparing coal to the cost of increasing generation at existing natural gas combined cycle (NGCC) power plants.

Windy states move up in the ranking

Texas ranks first in the nation with 7,200 megawatts (MW) of ripe-for-retirement coal capacity when compared to the cost of developing new wind projects. In contrast, Texas ranked 33rd with only 175 MW of economically vulnerable coal capacity compared to the cost of existing NGCC plants. Texas’ ranking under the wind scenario is not surprising given that it led the nation with 12,200 MW of installed wind capacity at the end of 2012, and the state has a significant untapped potential of low-cost wind resources still available.

Oklahoma also moved up in the ranking to number five, joining Michigan, Alabama, Georgia, Indiana, and Tennessee – each with more than 3,500 MW of coal capacity that is more expensive than new wind. The utilities with the most ripe-for-retirement coal capacity under our wind scenario are mostly located in those seven states. They include Southern Company, Tennessee Valley Authority (TVA), DTE Energy, OGE Energy Corp., NRG Energy, Texas Energy Future Holdings LP, American Electric Power (AEP), Xcel Energy, and CMS Energy Corporation.

Our wind scenario most likely represents a lower bound because we only compared coal plants to wind facilities located within the same region. But many power companies are finding better deals outside their regions. For example, several Southeast utilities such as Alabama Power and Georgia Power (subsidiaries of Southern Company), TVA, Arkansas Electric Cooperative, and Southwestern Electric Power Company have recently signed long-term contracts with wind projects in Oklahoma, Kansas, Texas, and the Upper Midwest based primarily on economics.

New wind technology has increased power output and lowered costs

The amount of economically vulnerable coal capacity compared to new wind projects is 8 GW higher than our 2012 study. The main reason for this is because we assumed higher capacity factors for wind to reflect new technology developments such as taller towers, longer blades, and advances in low wind speed turbines based on data from Lawrence Berkeley National Lab (LBNL) and recent projects. In addition, we assumed regional average capacity factors ranging from 35-47 percent rather than assuming a national average of 35 percent for all regions in our 2012 analysis.

As I discussed in a recent blog, LBNL data shows these higher capacity factors combined with reductions in capital costs has resulted in a 43 percent drop in U.S. average power purchase prices (PPAs) for wind over the past 3 years (from ~$70/megawatt-hour (MWh) in 2009 to below $40/MWh in 2012). This is consistent with our study which assumes regional costs ranging from $39-56/MWh with the PTC, and $58-76/MWh without the PTC (see figure below from the Electricity Journalarticle). To be conservative, these figures also include wind integration costs of $5/MWh based on studies by utilities and power system operators.

At these prices, our study shows wind is cheaper than existing coal plants retrofitted with pollution controls and existing NGCC plants in many parts of the country. This is consistent with a recent statement by Stephen Byrd, Morgan Stanley’s Head of North American Equity Research for Power & Utilities and Clean Energy:

“In the Midwest, we’re now seeing power agreements being signed with wind farms at as low as $25 per megawatt hour. Compare that to the variable cost of a gas plant at $30/MWh, the all-in cost to justify the construction of a new gas plant would be above $60/MWh.”

Our analysis assumes costs of $52/MWh for existing NGCC plants and $68/MWh for new NGCC plants based on EIA assumptions. Our costs from EIA are slightly higher than Byrd’s because we are assuming average fuel prices for natural gas over a 20-year period to compare with wind and coal investments.

Extending the PTC makes sense even with low wind costs

Without the PTC, our analysis shows that only 22 GW of existing coal capacity is ripe for retirement — less than one-third as much as the scenario with the PTC. The PTC, combined with state renewable energy standards, has been a key driver for the recent growth of the wind industry and the resulting cost reductions that have brought significant economic and environmental benefits at both the state and national level.

When Congress has allowed the PTC to expire in the past, the wind industry has fallen off a cliff. The PTC also helps level the playing field distorted by much larger, longer-term subsidies for fossil fuels and nuclear power that are still in place today. Smart policies like the PTC and carbon standards for new and existing power plants are needed to ensure a transition to cleaner, more affordable alternatives.

About the author:
Steve Clemmer is the director of energy research and an expert on the economic and environmental benefits of implementing renewable energy technologies and policies at the state and national levels. He holds a master’s degree in energy analysis and policy from the University of Wisconsin. See Steve's full bio.

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Tom Stacy

As Robert Bryce would say, “a burp in a hurricane.”

John Storm

The average reader may not understand that wind energy and coal-fired energy prices cannot be directly compared because they are not interchangeable. Consider EIA:

“The duty cycle for intermittent renewable resources, wind and solar, is not operator controlled, but dependent on the weather or solar cycle (that is, sunrise/sunset) and so will not necessarily correspond to operator dispatched duty cycles. As a result, their levelized costs are not directly comparable to those for other technologies (even where the average annual capacity factor may be similar) and therefore are shown in separate sections within the table.”

And there are massive differences in regional wind energy pricing. While some parts of IA, TX or ND may be selling wind at sub-$30/MWh prices (after significant subsidies worth at least $35/MWh pre-tax) many regions’ wind energy is selling for much higher prices. MI, for example, has a capacity weighted average price of $80/MWh and that price is locked in for the duration of the 20 year fixed price power purchase agreements, some with an annual escalator clause.

Those contracts will never get cheaper.

Steve Clemmer

You are correct that all-in levelized costs are not directly comparable since wind projects only produce electricity when the wind is blowing. Power system operators typically dispatch power plants based on their variable operating costs. Because wind power has no fuel costs, its variable operating costs are typically much lower than coal, natural gas, and even nuclear plants. So when wind projects are generating electricity, system operators will typically ramp down the most expensive power plants operating at that time, which are usually natural gas or coal plants. This in turn reduces wholesale electricity prices and saves consumers money, as shown in several recent studies:http://awea.rd.net/Resources/Content.aspx?ItemNumber=4594

However, for a new wind project (or any new power plant or pollution control retrofit for that matter) to be financed and built they need to have sufficient revenues to recover their fixed capital and operation and maintenance costs (and earn a profit). That’s why we included those costs in the cost comparison in our analysis. We also included a conservative wind integration cost of $5/MW, which several studies by utilities, power system operators, and government agencies have shown is sufficient to integrate up to 40% wind on a capacity basis (see p. 63 in the DOE/LBL 2012 Wind Technologies Market reporthttp://emp.lbl.gov/sites/all/files/lbnl-6356e.pdf)

Both EIA’s wind assumptions and your numbers for Michigan are outdated and pessimistic. They don’t reflect new technology developments that have significantly increased capacity factors or the recent drop in capital costs as cited in my blog. For example, a recent report from the Michigan Public Service Commission (MPSC) shows that the all-in costs of wind projects installed in Michigan has fallen from $100/MWh in 2008 to $50-60/MWh today, as capacity factors have increased from under 30 percent to 40 percent and above (see p. 6, 52 and 94 – 95 here http://www.michigan.gov/documents/energy/renewable_final_438952_7.pdf)

For comparison, EIA assumes a range of capacity factors for new wind projects of 30-39% to reflect regional differences (see footnote of table 2 in the link you sent) vs. new projects showing a range of ~35% to more than 50% in some cases. EIA also assumes national average capital costs for wind of more than $2,200/kW (p. 6 here http://www.eia.gov/forecasts/capitalcost/pdf/updated_capcost.pdf), which is 13% higher than data from the DOE/LBL report (p. 34 in link above) for a large sample of projects installed in the U.S. in 2012 at $1,940/kW.

http://www.ehspassistance.com Dale Francke

Has anyone studied and published results on the effect of wind power and windmill fields on overall, i.e. global, wind patterns? It seems to me that although we think wind power is free the energy taken from the wind affects the remaining air flow. How much of our current strange weather such as “super storms”, early snow storms and patterns, numbers and strength of tornadoes is due to changes in air patterns?

Steve Clemmer

Thanks for your question. It is true that as the number of wind turbines at a given site increases, the speed of the wind moving through the site decreases, which affects those turbines downwind. Wind developers take this “wind drag” or “wake loss” into account (along with other factors) when siting turbines in order to ensure optimal electricity generation. While more research is needed, a few recent studies estimate that large-scale development of wind power may be limited to around one watt per square meter of land (W/m2) when wind drag is taken into account. Fortunately, we have a long way to go before this level of density is reached: a 2012 study by the National Renewable Electricity Laboratory found that wind power could reliably supply about 40 percent of U.S. electricity use by 2050—up from 3.5 percent in 2012—with a production density of only 0.02 W/m2 averaged across the 48 contiguous states.

Some studies have shown that wind turbines can have an effect on local climatic conditions: because turbine blades mix the air, they tend to make surface air temperatures slightly warmer at night and slightly cooler during the day. However, these localized variations have little impact compared with the continuing rise in Earth’s average temperature due to increased global warming pollution from burning fossil fuels. Wind power generates no heat-trapping emissions during operation, thereby lessening the impact our nation’s electricity system has on the global climate.

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